Method and apparatus for cooling a hydrocarbon stream

ABSTRACT

A method of cooling a hydrocarbon stream such as natural gas, the method at least comprising the steps of:
         (a) providing a feed stream;   (b) passing the feed stream through a gas treatment stage comprising one or more (number: X) parallel gas treatment units, the feed stream being divided into two or more part-feed streams if there is more than one gas treatment unit, to provide one or more first treated streams;   (c) passing the first treated stream or streams of step (b) through an NGL extraction stage comprising one or more (number: Y) parallel NGL extraction units, the first treated stream or streams being shared to match the number of NGL extraction units, to provide one or more second treated streams; and   (d) passing the second treated stream or streams of step (c) through a cooling stage comprising one or more (number: Z) parallel cooling systems, the second treated stream or streams being shared to match the number of cooling systems, to provide a cooled hydrocarbon stream or streams.

This application claims priority from European Patent Application No.06124012.3, filed Nov. 14, 2006, which is incorporated herein byreference.

The present invention relates to a method and apparatus for cooling,optionally also liquefying, a hydrocarbon stream such as natural gas.

Several methods of liquefying a natural gas stream thereby obtainingliquefied natural gas (LNG) are known. It is desirable to liquefy anatural gas stream for a number of reasons. As an example, natural gascan be stored and transported over long distances more readily as aliquid than in gaseous form, because it occupies a smaller volume anddoes not need to be stored at a high pressure.

Usually natural gas, comprising predominantly methane, enters an LNGplant at elevated pressures and is pre-treated to produce a purifiedfeed stock suitable for liquefaction at cryogenic temperatures. Thepurified gas is processed through a plurality of cooling stages usingheat exchangers to progressively reduce its temperature untilliquefaction is achieved. The liquid natural gas is then further cooledand expanded to final atmospheric pressure suitable for storage andtransportation. The flashed vapour from each expansion stage can be usedas a source of plant fuel gas.

In addition to methane, natural gas usually includes some heavierhydrocarbons and impurities, including but not limited to carbondioxide, sulphur, hydrogen sulphide and other sulphur compounds,nitrogen, helium, water and other non-hydrocarbon acid gases, ethane,propane, butanes, C₅+ hydrocarbons and aromatic hydrocarbons. These andany other common or known heavier hydrocarbons and impurities eitherprevent or hinder the usual known methods of liquefying the methane,especially the most efficient methods of liquefying methane. Most if notall known or proposed methods of liquefying hydrocarbons, especiallyliquefying natural gas, are based on reducing as far as possible thelevels of at least most of the heavier hydrocarbons and impurities priorto the liquefying process.

Meanwhile, the capacity of a liquefaction plant is usually determined bythe availability of the gas feed stream, and the market or expectedmarkets for products provided by the plant. Thus, it can be desirable tobe flexible as to the capacity of the liquefaction plant. Hitherto,extra capacity at a liquefaction plant has simply involved the completereplication of all of the units dealing with the gas feed stream, fromits source to its storage. All such units are often termed a “train”.Some commonality of some units of a train or its support units such asrefrigeration units have been suggested, but no flexibility in thepre-treatment of the gas has been suggested.

The costs in creating and running a liquefying natural gas (LNG) plantor system are naturally high. Thus any flexibility and so reduction inthe energy requirements of the plant or system has significant costbenefit.

In a paper entitled “Large Capacity LNG Plant Development”, Paper PS5-3,J. J. B. Pek et al, presented at 14^(th) International Conference &Exhibition on Liquefied Natural Gas (Doha, Qatar), on 21 Mar. 2004,there is shown a general process for liquefying natural gas comprisingthe general steps of a gas receiving stage, a gas treating stage, apre-cooling stage which feeds two separate but parallel liquefactionstages, and an end flash stage to provide LNG to an LNG tank.

WO 2006/009646 A2 relates to a hydrocarbon fluid processing plantincluding a plurality of process unit module types, including first andsecond process unit module types having modules intended to be sized attheir respective substantially maximum processing efficiency. WO2006/009646 A2 shows a number of plant arrangements but a problem withthese arrangements is that there are always complete ‘trains’ fortreating and liquefying the hydrocarbon fluids, without flexibilitytherebetween.

It is an object of the present invention to improve the efficiency of atreatment plant or method.

It is a further object of the present invention to better streamline thehydrocarbon stream or streams through a treatment plant or method.

The present invention provides a method of cooling a hydrocarbon streamsuch as natural gas, the method at least comprising the steps of:

(a) providing a feed stream;(b) passing the feed stream through a gas treatment stage comprising oneor more (number: X) parallel gas treatment units, the feed stream beingdivided into two or more part-feed streams if there is more than one gastreatment unit, to provide one or more first treated streams;(c) passing the first treated stream or streams of step (b) through anNGL extraction stage comprising one or more (number: Y) parallel NGLextraction units, the first treated stream or streams being shared tomatch the number of NGL extraction units, to provide one or more secondtreated streams; and(d) passing the second treated stream or streams of step (c) through acooling stage comprising one or more (number: Z) parallel coolingsystems, the second treated stream or streams being shared to match thenumber of cooling systems, to provide a cooled hydrocarbon stream orstreams;wherein the number of parallel extraction units is higher than thenumber of parallel cooling systems.

In a further aspect, the present invention provides apparatus forcooling a hydrocarbon stream such as natural gas, the apparatus at leastcomprising:

(i) a gas treatment stage to receive a feed stream comprising one ormore (number: X) parallel gas treatment units, the feed stream beingdivided if there is more than one gas treatment unit;(ii) an NGL extraction stage to receive the treated feed stream orstreams from the gas treatment stage, comprising one or more (number: Y)parallel NGL extraction units; and(iii) a cooling stage to receive the NGL extracted stream or streamsfrom the NGL extraction stage, comprising one or more (number: Z)parallel cooling systems to provide a treated hydrocarbon stream orstreams;wherein the number of parallel NGL extraction units is higher than thenumber of parallel cooling systems.

The invention will now be further illustrated by way of example only,and with reference to embodiments, examples and the accompanyingdiagrammatic and non-limiting drawings in which:

FIG. 1 is a block scheme of part of an LNG plant according to oneembodiment of the present invention;

FIG. 2 is a block scheme of part of an LNG plant according to a secondembodiment of the present invention; and

FIG. 3 is a block scheme of part of an LNG plant according to a thirdembodiment of the present invention.

For the purpose of this description, a single reference number will beassigned to a line as well as a stream carried in that line. Samereference numbers refer to similar components.

The method and apparatus described herein comprises a gas treatmentstage, an NGL extraction stage and a cooling stage. The gas treatmentstage comprises one or more parallel gas treatment units; the NGLextraction stage comprises one or more parallel NGL extraction units;and the cooling stage comprises one or more parallel cooling systems.The number of gas treatment units will hereinafter be represented by theletter X; the number of NGL extraction units as Y, and the number ofcooling systems as Z.

For the purpose of this specification, “parallel” means arranged oroperated in parallel with respect to other units or systems of same typewhen more than one of that type of unit or system is provided or alonewhen one unit or system of a type is provided.

As described herein, an asymmetric arrangement between the number of gastreatment units, the number of NGL extraction units, and the number ofcooling systems is provided. An asymmetric configuration offers benefitsin terms of overall plant availability and matching of individual unitequipment sized design capacity constraints.

In an advantageous group of embodiments, the number of NLG extractionunits is higher than the number of cooling systems (i.e. Y>Z). Thisadvantageous choice is based on an insight that limits in vapourexpander size are typically more restrictive than the size of a coolingsystem in terms of production capacity. NGL extraction units aretypically based on an expander. Thus, production capacity can beincreased by operating in parallel more expander-based extraction unitsthan there are cooling systems.

Moreover, providing Y>Z offers the possibility of providing an excess ofNGL extraction capacity relative to cooling capacity. Generating excessNGL-extracted gas may be useful to provide domestic gas from ahydrocarbon stream cooling site.

In another group of embodiments, X or Y, preferably X and Y both, areunequal to Z, whereby at least one of X and Y is greater than one.

The asymmetry provided herein also allows the energy requirements of theliquefaction facility or plant to be more balanced.

An asymmetric configuration also offers the user of a plant options andflexibility should a gas treatment unit or an NGL extraction unit beoff-line, i.e. non-operational, either accidentally or deliberately formaintenance, etc. Whilst there may be some reduction in plant output orin one or more stream flows, overall, the plant can remain operationalthrough the use of other gas treatment units and NGL extraction units.

In the gas treatment stage, the level or levels of certain impuritiesgenerally not being hydrocarbons can be reduced. Two common impuritiesare carbon dioxide and sulphur (and sulphur-based compounds), usuallypresent with water in the form of ‘acid gas’. Many processes for theremoval of acid gas from a feed stream are known to those skilled in theart. One common method is the use of an aqueous amine solution, oftenused in an extraction column termed a ‘scrubber’. The aqueous amine maybe one or more of known materials including for example DGA, DEA, MDEA,MEA and SULFINOL™ (Shell), and combinations thereof. Typically acid gasremoval can result in the reduction of carbon dioxide to levels of lessthan about 60 ppm, whilst sulphur can be reduced to levels of less thanabout 4 ppm. The gas treatment stage comprises one or more parallel gastreatment units. By “gas treatment unit” is meant a unit comprising oneor more solvent-fed extraction columns which remove acid gas from thehydrocarbon stream under elevated pressure (relative to solventregeneration pressure) to produce enriched solvent and a treatedhydrocarbon stream. The enriched solvent is then passed within the gastreatment unit to one or more pressure let-down devices and then to oneor more heaters or regeneration columns which separate the solvent fromthe acid gas and recycle at least a portion of the solvent to the one ormore extraction columns. The extraction columns and heaters orregeneration columns of the gas treatment unit represent equipment whichis dedicated to a single gas treatment unit such that they are notshared with any other gas treatment units.

The NGL extraction stage comprises one or more parallel NGL extractionunits. By “NGL extraction unit” is meant a unit comprising one or moreknock-out drums from which the hydrocarbon stream is passed, via anexpansion step, to one or more NGL separators which produce an NGLstream or streams, which each comprise, for instance, less than 5 mole %methane. The knock-out drums and NGL separators of the NGL extractionunit represent equipment which is dedicated to a single NGL extractionunit such that they are not shared with any other NGL extraction units.However, subsequent separation of the NGL stream into individualhydrocarbon streams, often referred to as fractionation, can be carriedout in a facility shared between NGL extraction units.

NGL extraction units as such are known to those skilled in the art.Generally, they are designed to reduce the level or levels ofhydrocarbon compounds other than methane in a feed stream. One commonNGL extraction unit includes a separator or separation vessel, able toprovide a gaseous stream that is methane-enriched, and one or more otherstreams. Such other stream or streams usually but not always includeseparate or combined streams of heavier hydrocarbons. Themethane-enriched stream may be passed through the cooling stage.

In one example, an NGL extraction unit provides a single heavierhydrocarbon rich stream, which is subsequently used either per se, or isfurther divided into particular heavier hydrocarbon rich streams in aseparate location or unit. The division of a heavier hydrocarbon richstream can be carried out by one or more separators known in the art,such as a fractionator. A fractionator using one or more columns couldprovide individual streams of certain heavier hydrocarbons. For example,with multiple columns, each column could be designed to provide anindividual hydrocarbon stream, such as an ethane-rich stream, apropane-rich stream, a butane-rich stream, and a C₅+-rich stream, thelatter sometimes also termed a ‘light condensate stream’. Propane,butane and C₅+ hydrocarbons are sometimes collectively termed “naturalgas liquids” (NGL), and have known uses.

An example of a fractionation tower as a conventional distillationcolumn for NGL extraction is shown in US 2004/0079107 A1.

In another example, an NGL extraction unit can include a fractionatorwhich integrally provides individual streams of certain heavierhydrocarbons such as those listed hereinbefore.

Cooling systems for the cooling stage are known in the art. The coolingsystem may be a liquefying system. Cooling systems and liquefyingsystems may be embodied in various ways, and generally involve one ormore heat exchangers and refrigerant circuits.

The cooling stage comprises one or more parallel cooling systems. By“cooling system” is meant a cooling system comprising one or moreclosed, independent refrigerant cycles. A closed refrigerant cycle doesnot exchange refrigerant with another cooling cycle under normaloperation. The closed, independent refrigerant cycle or cycles arededicated to a single cooling system such that they are not shared withany other cooling systems.

A liquefying system useable with the present invention may involve anumber of separate serial cooling steps, and the or each cooling stepmay involve one or more heat exchangers, levels or sections. Onearrangement involves the cooling stage having a first cooling step forpre-cooling, followed by a second cooling step for main cryogeniccooling and liquefying.

A first or pre-cooling step may involve reducing the temperature of afeed stream to below −0° C., for example in the range −10° C. to −30° C.

A second or main cryogenic cooling step may involve cooling a feedstream to below −90° C. or below −100° C., for example between −100° C.to −130° C., which usually creates a hydrocarbon stream which is nowliquefied, such as liquefied natural gas.

Each unit or system of the stages of the present invention may use thesame or different parameters, such as flowrate, temperature, pressure,etc.

By providing units and systems which may operate independently, a unitor system may be taken off-line for maintenance without having to shutdown the entire hydrocarbon cooling plant.

The present invention includes a combination of any and all of themethods herein described.

As described herein, the number of streams for each of the stages isintended to be shared to match the number of units or systems in eachstage. This may therefore require the division, sharing or combinationof the feed stream or the stream or streams provided by the previousstage. Such division, sharing and/or combination may or may not involvethe complete mixing of previous streams, or the complete separation ofprevious streams.

Any division, sharing and/or combination of the feed stream or stream orstreams provided by a previous stage may be unequally distributed.Preferably the distribution is equal, that is, there is equidistributionof the stream or streams amongst the lines to the units or systems towhich the stream or streams are intended to be passed to.

The division or sharing of any of the feed streams or any of thesubsequent treated or cooled hydrocarbon stream or streams, could beprovided by any suitable divisor, for example a stream splitter.Preferably any division or sharing creates two or more streams havingthe same composition and phases.

All possible arrangements for changes in the number of streams before orafter each stage are envisaged. For example, where X is 1, Y is 2 and Zis 1, the first treated stream provided by the gas treatment stage isdivided into two first treated streams for each of the NGL extractionunits in the NGL extraction stage. The two second treated streamsprovided thereby are then combined into a single second treated streamfor the single cooling system in the cooling stage.

In another example, X can be 2, Y can be 3, and Z can be 2. In thisexample, the feed stream is shared or divided into two part-feed streamsfor the two gas treatment units in the gas treatment stage. The twofirst treated streams provided thereby are then shared to provide threefirst treated streams, one for each of the NGL extraction units in theNGL extraction stage. The change from two to three first treated streamsmay be through a common manifold, or may be by any other sharingarrangement not having a common union or junction of all streams.Similarly, the three second treated streams provided by the NGLextraction stage are then shared to create two second treated streamsfor the two cooling systems. This sharing of the second treated streamsmay be through a common manifold, or through any other arrangement notinvolving commonality or union of all the second treated streams.

The present invention may also be used to create a facility or plantwhere X is 2, Y is 2 and Z is 1. Should there be a wish or need toenlarge the capacity of the facility or plant, one or more further gastreatment units, NGL extraction units, and/or cooling systems, can beadded, taking into account the design capacity of existing units,thereby avoiding the hitherto expedient of having to supply a completeand separated liquefaction ‘train’.

The feed stream may be any suitable hydrocarbon-containing gas stream tobe cooled, but is usually a natural gas stream obtained from natural gasor petroleum reservoirs. As an alternative the natural gas stream mayalso be obtained from another source, also including a synthetic sourcesuch as a Fischer-Tropsch process.

Usually the natural gas stream is comprised substantially of methane.Preferably the feed stream comprises at least 60 mol % methane, morepreferably at least 80 mol % methane.

Although the method described herein is applicable to varioushydrocarbon feed streams, it is particularly suitable for natural gasstreams to be liquefied. As the person skilled readily understands howto liquefy a hydrocarbon stream, this is not further discussed here.

FIG. 1 shows a block scheme of part of a liquefied natural gas plant 1.It shows an initial feed stream 10 containing natural gas. The feedstream 10 is divided by a stream splitter 12 into two part-feed streams20 a, 20 b. The division of the feed stream 10 could be based on anyratio of mass and/or volume and/or flow rate. The ratio may be based onthe size or capacity of the subsequent parts, systems or units of theplant, or due to other considerations. One example of the ratio is anequal division of the cooled stream mass.

The two part-feed streams 20 a, 20 b pass to a gas treatment stage 2comprising two parallel gas treatment units 14 a, 14 b. Such gastreatment units 14 a, 14 b are adapted to reduce impurities, includingbut not limited to acid gas, in the part feed-streams 20 a, 20 b, and soprovide two first treated streams 30 a, 30 b respectively. Operation ofgas treatment units 14 a, 14 b such as scrubbers are well known in theart. FIG. 1 shows an exit stream 15 a, 15 b for carbon dioxide, sulphurand any sulphur-based compounds from each gas treatment unit 14 a, 14 b.

The first treated streams 30 a, 30 b are passed to an NGL extractionstage 4 which comprises two parallel NGL extraction units 16 a, 16 b.The NGL extraction units 16 a, 16 b provide two second treated streams40 a, 40 b, which streams are methane-enriched, and which are combinedto provide a combined treated stream 50. The second treated feed streams40 a, 40 b can be combined using a combiner 18 known in the art. Thecombiner may be any suitable arrangement, generally involving a union orjunction or piping or conduits, optionally involving one or more valves.

The NGL extraction units 16 a, 16 b also provide two heavier hydrocarbonenriched streams 17 a, 17 b which pass to a common fractionator 24. Theenriched streams 17 a, 17 b may be combined prior to entry into thecommon fractionator 24 as shown in FIG. 1, or may be passed separatelyinto the common fractionator 24.

The common fractionator 24 is designed to provide separate enrichedstreams of one or more hydrocarbons such as propane, butane and C₅+hydrocarbons, and optionally also ethane. Such enriched streams areuseful products for use in the liquefying plant 1 or outside the plant.Such enriched streams are shown collectively in FIG. 1 as streams 26.

The fractionator 24 may be a single fractionation unit, or have one ormore columns, wherein each column is usually dedicated to separating andproviding a particular heavier hydrocarbon. Fractionation is well knownin the art and the benefit and use of individual streams of propane,butane and C₅+ are also well known in the art.

Although not shown in FIG. 1, any methane stream or methane-enrichedstream provided by the fractionator 24 may be returned or recycled backinto the path of the second treated streams 40 a, 40 b or the combinedstream 50.

The combined treated stream 50 is then passed to a cooling stage 6. InFIG. 1, the cooling stage 6 provides a cooled hydrocarbon stream 60.

The cooling of the combined treated stream 50 in the cooling stage 6 mayinvolve any degree of cooling using any number of units, devices orsystems or combinations thereof known in the art. One example is the useof one or more heat exchangers. Usually, cooling is effected by passingthe combined treated stream 50 against one or more cooling orrefrigerant streams and/or through one or more valves and/or separators,as known in the art.

In one embodiment of the present invention, the cooling stage 6 isadapted to liquefy the combined treated stream 50 so as to provide aliquefied hydrocarbon stream such as liquefied natural gas. Liquefactionof the combined treated stream 50 can be carried out by passing itthrough a cooling system being a liquefying system 22 using one or moreheat exchangers and cooling it against one or more refrigerants, eitherbeing dedicated refrigerants or other cooled streams. The liquefying caninvolve one or more cooling and/or liquefying steps.

Generally, it is intended to provide a liquefied natural gas streamhaving a temperature below −150° C., more usually between −160° C. and165° C.

Between the gas treatment stage 2, NGL extraction stage 4 and thecooling stage 6, one or more other units or features may be involvedsuch as valves or further treatments, or to control of the path or flowof the streams thereinbetween.

FIG. 1 shows a method of treating a hydrocarbon stream such as naturalgas wherein X is 2, Y is 2, and Z is 1. There is therefore asymmetrybetween the number of gas treatment units, the number of NGL extractionunits, and the number of cooling systems. An asymmetric configuration,particularly where Y>Z as in the embodiment of FIG. 1, offers benefitsas explained hereinabove.

FIG. 2 shows a block scheme of part of a liquefied natural gas plant 1 aaccording to a second embodiment of the present invention. In FIG. 2, afeed stream 10 is divided by a divider 12 into three part-feed streams20 a, 20 b and 20 c, either equally or unequally as described above. Thethree part-feed streams 20 a, 20 b, 20 c pass into three respective andparallel gas treatment units 14 a, 14 b and 14 c which comprise the gastreatment stage 2. The action and effect of the gas treatment units 14a, 14 b, 14 c is similar to those described hereinbefore. They providethree first treated streams 30 a, 30 b, 30 c, and three other streams 15a, 15 b, 15 c, being for example, sulphur, carbon dioxide, etc.

The three first treatment streams 30 a,b,c pass into respective andparallel NGL extraction units 16 a, 16 b, 16 c, whose action and effectis similar to those described hereinbefore. The units 16 a, 16 b, 16 cprovide three second treated streams 40 a, 40 b, 40 c which are thenshared for the cooling stage 6, and three heavier hydrocarbon streams 17a, 17 b, 17 c, whose use and/or separation can be the same or similar tothat described above in FIG. 1.

The sharing of the three second treated streams 40 a, 40 b, 40 c may notinvolve the complete combination and mixing of the second treatedstreams 40 a, 40 b, 40 c within one position, location, line or stream.Thus, references herein to the second treated streams being “shared”,include the second treated streams being able to provide one or morestreams to a cooling stage, which cooling stage may comprise one or morecooling systems. The one or more streams supplying the cooling system orsystems may therefore comprise flow from two or more second treatedstreams, without involving flow from all of the second treated streams.

It is intended by the present invention that all the second treatedstreams collectively supply their flow to the or all of the coolingsystems of the cooling stage.

In FIG. 2, it is diagrammatically represented that the three secondtreated streams 40 a, 40 b, 40 c provide, via linked piping or conduitsat junctions 19 a, 19 b, combined treated streams 50 a, 50 b, which passrespectively into two cooling systems 22 a, 22 b which comprise thecooling stage 6. The cooling systems 22 a, 22 b preferably liquefy thecombined treated streams 50 a, 50 b to provide two liquefied hydrocarbonstreams 52 a, 52 b, which can be combined to provide a combinedliquefied hydrocarbon stream 60, such as liquefied natural gas.

Thus, FIG. 2 shows a method of treating a hydrocarbon stream such asnatural gas wherein X is 3, Y is 3, and Z is 2.

FIG. 3 shows a simplified block scheme of part of a liquefied naturalgas plant 1 b according to a third embodiment of the present invention.In FIG. 3, a feed stream 10 passes into a single gas treatment unit 100for the gas treatment stage 2. The action and effect of the gastreatment unit 100 is similar to those described hereinbefore. Thisprovides a first treated stream 30 d which is optionally passed througha separate or integral drying unit 101 to reduce its water content, andprovide a drier treated stream 30 e.

The drier treated stream 30 e is then divided by a divider 32,preferably equally, into 3 part-streams 30 f, 30 g, 30 h, which passinto three respective and parallel NGL extraction units 102 a, 102 b and102 c, whose action and effect is similar to those describedhereinbefore, and which comprise the NGL extraction stage 4. The units102 a, b, c provide three second treated streams 40 a, 40 b, 40 c, whichare then combined using a combiner 34 to provide a single combinedstream 50.

The combined stream 50 is then divided by a divider 36 into twopart-streams 50 a, 50 b, optionally unequally or equally, to pass intotwo cooling systems 103 a, 103 b, similar to those described above, andwhich comprise the cooling stage 6. The cooling systems 103 a,b arepreferably adapted to liquefy the part-streams 50 a, 50 b, to providetwo liquefied hydrocarbon streams 52 a, 52 b, which can then be combinedby a combiner 38 to provide a combined liquefied hydrocarbon stream 60,such as liquefied natural gas. The liquefied natural gas 60 can passthrough an endflash unit 104 in a manner commonly known in the art, toprovide a final liquefied product stream 70.

Thus, FIG. 3 shows another embodiment of the present invention having agas treatment stage with one gas treatment unit, an NGL extraction stagehaving three NGL extraction units, and a cooling stage comprising twoparallel cooling systems, i.e. a method of treating a hydrocarbon streamsuch as natural gas wherein X is 1, Y is 3, and Z is 2.

The person skilled in the art will understand that the present inventioncan be carried out in many various ways without departing from the scopeof the appended claims.

1. Method of cooling a hydrocarbon stream such as natural gas, themethod at least comprising the steps of: (a) providing a feed stream;(b) passing the feed stream through a gas treatment stage comprising oneor more (number: X) parallel gas treatment units, the feed stream beingdivided into two or more part-feed streams if there is more than one gastreatment unit, to provide one or more first treated streams; (c)passing the first treated stream or streams of step (b) through an NGLextraction stage comprising one or more (number: Y) parallel NGLextraction units, the first treated stream or streams being shared tomatch the number of NGL extraction units, to provide one or more secondtreated streams; and (d) passing the second treated stream or streams ofstep (c) through a cooling stage comprising one or more (number: Z)parallel cooling systems, the second treated stream or streams beingshared to match the number of cooling systems, to provide a cooledhydrocarbon stream or streams; wherein Y>Z.
 2. Method as claimed inclaim 1, wherein the feed stream is divided into two part-feed streams,and X is 2 and Z is
 1. 3. Method as claimed in claim 1, wherein Y is 2and Z is
 1. 4. Method as claimed in claim 1, wherein the feed stream isdivided into three part-feed streams, and X is 3 and Z is 1 or
 2. 5.Method as claimed in claim 1, wherein Y is 3 and Z is 1 or
 2. 6. Methodaccording to claim 1, wherein the or each NGL extraction unit provides asecond treated stream and one or more separate streams.
 7. Method asclaimed in claim 6, wherein the one or more separate streams compriseone or more of a propane stream, a butane stream and a C₅+ stream. 8.Method as claimed in claim 6, wherein the one or more separate streamsare fractionated to provide one or more fractionated streams.
 9. Methodas claimed in claim 7, wherein the one or more fractionated streamscomprise one or more of a propane stream, a butane stream and a C₅+stream.
 10. Method according to claim 1, wherein X is different from Z.11. Method according to claim 1, wherein the cooling step (d) liquefiesthe second treated stream or streams to provide a liquefied hydrocarbonstream or streams.
 12. Liquefied hydrocarbons comprising the liquefiedhydrocarbon stream obtained from the method of claim
 11. 13. Apparatusfor cooling a hydrocarbon stream such as natural gas, the apparatus atleast comprising: (i) a gas treatment stage to receive a feed streamcomprising one or more (number: X) parallel gas treatment units, thefeed stream being divided if there is more than one gas treatment unit;(ii) an NGL extraction stage to receive the treated feed stream orstreams from the gas treatment stage, comprising one or more (number: Y)parallel NGL extraction units; and (iii) a cooling stage to receive theNGL extracted stream or streams from the NGL extraction stage,comprising one or more (number: Z) parallel cooling systems to provide atreated hydrocarbon stream or streams; wherein Y>Z.
 14. Apparatus asclaimed in claim 13, wherein X is 2 and Z is
 1. 15. Apparatus as claimedin claim 13, wherein Y is 2 and Z is
 1. 16. Apparatus as claimed inclaim 13, wherein X is 3 and Z is 1 or
 2. 17. Apparatus as claimed inclaim 13, wherein Y is 3 and Z is 1 or
 2. 18. Apparatus as claimed inclaim 13, further comprising a fractionator to fractionate all of one ormore separate streams provided by the NGL extraction units. 19.Apparatus according to claim 13, wherein X is different from Z. 20.Apparatus as claimed in claim 13, wherein the or each cooling system isa liquefying system.
 21. Method as claimed in claim 2, wherein Y is 2and Z is
 1. 22. Method as claimed in claim 4, wherein Y is 3 and Z is 1or
 2. 23. Method according to claim 1, wherein the cooling step (d)liquefies the second treated stream or streams to provide liquefiednatural gas.
 24. Apparatus as claimed in claim 14, wherein Y is 2 and Zis
 1. 25. Apparatus as claimed in claim 16, wherein Y is 3 and Z is 1 or2.